Gas turbine control system having optimized ignition air flow control

ABSTRACT

Method and apparatus for generating an ignition enabling signal for use with a given combustion turbine having an ignition system which ignites the turbine in response to an enabling signal, wherein a turbine speed signal is given, is shown to include a sensor for generating an ambient air temperature signal, a reference member for generating a reference signal representative of the turbine speed at which optimum air flow exists for ignition, a comparator for comparing the reference signal to an adjusted speed signal and for generating the ignition enabling signal when the adjusted speed signal exceeds the reference signal and for providing the enabling signal to the ignition system. The adjusted speed signal is generated by modifying the turbine speed signal in response to the ambient air temperature signal. Such modification is achieved by summing the turbine speed signal with a bias speed factor. The bias speed factor is representative of the difference between optimum turbine ignition speed and that turbine speed necessary for optimum ignition air flow to exist in said combustion turbine at such ambient temperature.

FIELD OF THE INVENTION

The present invention relates generally to the field of combustionturbines and more particularly to the field of ignition control systemsfor combustion turbines. Although the present invention may findparticular utility in the field of gas turbine electric power plants,and will be described in relation to such equipment, the invention canalso be applied to combustion turbines having other uses.

BACKGROUND OF THE INVENTION

Gas turbine electric power plants are utilized in so-called base load,mid-range load and peak load power system applications Combined cycleplants are normally used for the base or mid-range applications whilethe power plant which utilizes a single gas turbine as the generatordrive is highly useful for peak load applications because of itsrelatively low cost.

In the operation of gas turbines, particularly in electric power plants,various kinds of control systems have been employed from relay-pneumatictype systems, to analog type electronic controls, to digital controls,and more recently to computer based software controls. U.S. Pat. No.4,308,463--Giras et al., assigned to the assignee of the presentinvention and incorporated herein by reference, lists several of suchprior systems. That patent also discloses a digital computer basedcontrol system for use with gas turbine electric power plants. It can besaid that the control system described in U.S. Pat. No. 4,308,463 is apredecessor to the system described in the present invention. It will benoted that the Giras et al. patent is one of a family of patents all ofwhich are cross referenced therein.

Subsequent to the Giras et al. patent, other control systems have beenintroduced by Westinghouse Electric Corporation of Pittsburgh, Pa. underthe designations POWERLOGIC and POWERLOGIC II. Similar to the Giras etal. patent these control systems are used to control gas tubrineelectric power plants. However, such control systems are primarilymicro-processor based computer systems, i.e. the control systems areimplemented in software, whereas prior control systems were implementedin electrical and electronic hardware.

The operating phiolosophy behind the POWERLOGIC and POWERLOGIC IIcontrol system is that it shall be possible for the operator to bringthe turbine generator from a so-called ready-start condition to fullpower by depressing a single button. All modes of turbine-generatoroperation are to be controlled including control of fuel flow furinglarge step changes in required power output.

The present invention constitutes an improvement to the POWERLOGIC IIsystem. Ignition in prior combustion turbines, for example the W501D5,utilize compressor discharge pressure as a measure for determining whenignition should occur. Unfortunately, this so-called constant pressureignition is effected by ambient conditions such as air temperature andthe temperature of the metal parts of the turbine itself. It can beshown that ambient temperature can effect air flow through a combustionturbine by as much as 6 percent. The possibility exists that certainfuel/air conditions which are outside the ignition envelope of thecombustion turbine could occur. Consequently, a need exists for morereliably determining when optimum conditions re present for the ignitionprocess.

Although, the operation of a gas turbine electric power plant and thePOWERLOGIC II control system are described generally herein, it shouldbe noted that the invention is particularly concerned with enabling theignition process in gas turbines.

SUMMARY OF THE INVENTION

It is an object of the present invention to provide an electric powerplant having a combustion turbine driven generator and a controller forsensing optimum air flow and for enabling the ignition process whenoptimum airflow conditions are present.

It is another object of the present invention to provide a turbinecontrol system which controls the enablement of the ignition process sothat ignition occurs during optimum air flow conditions.

It is still another object of the present invention to generate anignition enable control signal which is representative of turbine speedadjusted to account for ambient air temperature.

It is yet another object of the present invention to generate anignition enable control signal which is representative of turbine speedadjusted to account for ambient air temperature wherein a bias factor isadded to actual turbine speed.

These and other objects of the invention are achieved by method andapparatus for generating an ignition enabling signal for use with agiven combustion turbine, wherein a turbine speed signal is given, andincludes a sensor for generating an ambient air temperature signal, areference member for generating a reference signal representative of theturbine speed at which optimum air flow exists for ignition, acomparator for comparing the reference signal to an adjusted speedsignal and for generating the ignition enabling signal when the adjustedspeed signal exceeds the reference signal. The adjusted speed signal isgenerated by modifying the turbine speed signal in response to theambient air temperature signal. Such modification is achieved by summingthe turbine speed signal with a bias speed factor. The bias speed factoris representative of the difference between optimum turbine ignitionspeed and that turbine speed necessary for optimum ignition air flow toexist in said combustion turbine at such ambient temperature.

These and other objects and advantages of the invention will become moreapparent from the following detailed description when taken inconjunction with the following drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a top plan view of a gas turbine power plant arranged tooperate in accordance with the principles of the present invention;

FIGS. 2 and 3 show respective electrical systems useable in theoperation of the gas turbine power plant of FIG. 1;

FIG. 4 shows a schematic view of a rotating rectifier exciter and agenerator employed in the gas turbine power plant of FIG. 1;

FIG. 5 shows a front elevational view of an industrial gas turbineemployed in the power plant of FIG. 1;

FIGS. 6-8 show a fuel nozzle and parts thereof employed in the gasturbine of FIG. 5;

FIGS. 9 and 10 respectively show schematic diagrams of gas and liquidfuel supply systems employed with the gas turbine of FIG. 5;

FIG. 11 shows a block diagram of a digital computer control systememployed to operate the gab turbine power plant of FIG. 1;

FIG. 12 shows a schematic diagram of a control loop which may beemployed in operating the computer control system of FIG. 11; and

FIG. 13 shows a schematic diagram of the control circuit of the presentinvention for sensing optimum air flow and enabling the ignitionprocess.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

A new and novel system for controlling fuel flow in a combustionturbine-generator during load transients is described in relation toFIG. 13 herein, particularly for use in controlling fuel flow duringlarge step changes in required power output. Although the presentinvention can be implemented in either software or hardware, in thepreferred embodiment it is implemented in soft ware contained in acentral processing unit to be described herein. However, beforedescribing the particular program of the present invention considerfirst an overall description of the operating environment for theinvention, namely a gas turbine powered electric power plant.

There is shown in FIG. 1 a gas turbine electric power plant 100 whichincludes AC generator 102 driven by combustion or gas turbine 104. Inthe embodiment described herein, gas turbine 104 is preferably the W501D5 type manufactured by Westinghouse Electric Corporation.

A typical use of power plant 100 is where continuous power generation isdesired and the exhaust heat from gas turbine 104 is desired for aparticular purpose such as feedwater heating, boiler, or economizers. Inaddition to the advantage of relatively low investment cost, power plant100 can be located relatively close to load centers, i.e. populationcenters or manufacturing sites, as indicated by system requirementswithout the need for a cooling water supply thereby advantageouslyproducing a savings in transmission facilities. Further, power plant 100can be left relatively unattended and automatically operated from aremote location.

Community acceptance of power plant 100 is enhanced by the use of inletand exhaust silencers 108 and 110 which are coupled respectively toinlet and exhaust ductworks 112 and 114. Fast startup and low standbycosts are additional operating advantages characteristic to power plant100.

Power plant 100 can be provided with an enclosure (not shown) in theform of a rigid frame-type sectional steel building. Buildings of thistype typically comprise rigid structural steel frames covered bysectional type panels on the roof and walls. The roof and wallconstruction is designed for minimum heat loss and minimum noisepenetration while enabling complete disassembly when required.

In order to gain an appreciation of the size of the power plantdescribed herein, the foundation for plant 100 is approximately 106 feetlong if a control station is provided for a single plant unit. Thefoundation length can be increased as indicated by the referencecharacter 116 to provide for a master control station. A master controlstation would be warranted if additional plant units, grouped with plant100, are to have common control. Although the present invention can beutilized in a master control setting for multiple power plants, forsimplicity, the invention is described herein in relation to only asingle turbine generator.

Micro-processor based computers and other control system circuitry incabinet 118 provides for operation and control of power plant 100. Inthe preferred embodiment, cabinet 118 includes WDPF equipment sold byWestinghouse Electric Corporation and can include two distributedprocessing units, an engineers console and a logger. Such other controlsystem circuitry would include appropriate input/output (I/O) circuitrynecessary for interfacing the computer control systems with variousoperating equipment and condition sensors. An operator's cabinet 120,associated with the control cabinet 118, contains vibration monitor,electronics for UV flame detectors, a synchroscope, various push-buttonswitches, an industrial computer and electromechanical counters andtimers. An automatic send/receive printer 122 and a protective relaypanel 124 for sensing abnormal electric power system conditions areassociated with the control cabinet 118.

Startup or cranking power for the plant 100 is provided by a startingengine 126 which in the preferred embodiment is an AC motor unit.Starting engine 126 is mounted on an auxiliary bedplate and coupled tothe drive shaft of gas turbine 104 through a starting gear unit 128.During the initial startup period, AC motor 128 operates through aturning gear 130 and starting gear 132 to drive the gas turbine. Whenturbine 104 reaches approximately 20 percent of rated speed, ignitiontakes place. AC motor 128 continues to operate until turbine 104 reachessustaining speed. AC motor 128 can be operated for longer periods ifturbine disc cavity temperature is excessive, in order to avoidthermally induced shaft bowing.

A motor control center 134 is also mounted on the auxiliary bedplate andit includes motor starters and other devices to provide for operation ofthe various auxiliary equipment items associated with the plant 100.Electrical breakers for motor control center 134 are preferably frontmounted. Various signals from sensor or contact elements associated withmotor control center 134 and with other devices mounted on the auxiliarybedplate are transmitted for use in the control system as consideredmore fully in connection with FIG. 11.

A plant battery 135 is disposed adjacent to one end of the auxiliarybedplate or skid. A battery charger, described in relation to FIG. 11,is connected to the motor control center 134 through a breaker (notshown). Battery 135 can be any heavy duty control battery such as theEHGS-17 EXIDE rated at 125 volts, 60 cells. In any event, battery 135should be capable of supplying adequate power for emergency lighting,auxiliary motor loads, AC computer supply voltages and other controlpower for one hour following shutdown of the plant 100.

One possible internal electrical power system for use with plant 100 isshown generally in FIG. 2. Once plant 100 is in operation, powergenerated by generator 102 is transmitted to the power system throughgenerator breaker 136, through 13.8 KV bus 137 to a main transformer(not shown) and line breaker 138. Auxiliary power for the plant 100 isobtained from the internal power system through an auxiliary breaker 139and an auxiliary power 480 volt bus 140. The generator breaker 136serves as a and protective disconnect device for the plant 100.

If a suitable 480 volt source is not available in the internal powersystem, an auxiliary power transformer 141 can be provided as shown inFIG. 3. A disconnect switch 142 is connected between transformer 141 andthe station 13.8 KV bus 137. The arrangement as shown in FIG. 3 canprovide for so-called black plant startup operation. With thisarrangement, gas turbine 104 may be started at any time, since theauxiliaries may be supplied from either generator 102 or the internalpower system, whichever is energized. In a black start, i.e. a deadsystem, gas turbine 104 may be started at any time for availability as aso-called spinning standby power source, even though the external powersystem, to which plant 100 is connected, is not ready to accept powerfrom generator 102. Further, the circuits shown in FIGS. 2 and 3 allowplant 100 to be separated from an external power system in troublewithout shutting down gas turbine 104. The breaker nearest the powersystem load would be tripped to drop the load and let generator 102continue to run and supply its own auxiliaries.

An additional advantage of the scheme shown in FIG. 3 is the protectionprovided if the connection to the power system is vulnerable to apermanent fault between plant 100 and the next breaker in the system. Insuch a situation line breaker 138 would be the clearing breaker in caseof such a fault and the auxiliary system would remain energized bygenerator 102 which would allow an orderly shutdown of the gas turbine104 or continued operation as standby.

The arrangement of FIG. 3 is preferable if gas turbine 104 is programmedto start during a system low voltage or decaying frequency situation.During such events, automatic startup could bring turbine 104 up tospeed, close generator breaker 136 and supply power to the auxiliaryload. The turbine-generator unit would then be running and would beimmediately available when desired. The arrangement of FIG. 3 can alsobe utilized if an under-frequency or under-voltage signal is to be usedto separate the gas turbine 104 from the system.

A switchgear pad 143 is included for 15 KV switchgear 144, 145 and 146,including generator breaker 136. The auxiliary power transformer 141 anddisconnect switch 142 are also disposed on switchgear pad 143 if theyare selected for use by the user. Excitation switchgear 150 associatedwith the generator excitation system is also included on the switchgearpad 143. As will be described in greater detail hereinafter, the I/Ocircuitry of cabinet 118 accepts signals from certain sensor or contactelements associated with various switchgear pad devices.

A pressure switch and gauge cabinet 152 is also included on theauxiliary bedplate. Cabinet 152 contains the pressure switches, gauges,regulators and other miscellaneous elements needed for gas turbineoperation.

Although not specifically shown, it should be understood that plant 100also incorporates a turbine high pressure cooling system and aradiation-type air-to-oil cooler for lubrication oil cooling. Suchdevices can be of any known design.

Generator 102, including brushless exciter 154, is schematicallyillustrated in greater detail in FIG. 4. The rotating elements ofgenerator 102 and exciter 154 are supported by a pair of bearings 158and 160. Conventional generator vibration transducers 162 and 164 arecoupled to bearings 158 and 160 for the purpose of generating input datafor the plant control system. A grounding distribution transformer withsecondary resistors (not shown) is provided to ground the generatorneutral.

Resistance temperature detectors (RTD) 181 A-F, embedded in the statorwinding, are installed to measure the air inlet and dischargetemperatures and the bearing oil drain temperatures as indicated in FIG.4. Signals from the temperature sensors and vibration transducers 162and 164 are transmitted to the control system, i.e. cabinet 118.

In the operation of the exciter 154, a permanent magnet field member 165is rotated to induce voltage in a pilot exciter armature 166 which iscoupled to a stationary AC exciter field 168 through a voltage regulator(not shown). Voltage is thereby induced in an AC exciter armature 172formed on the exciter rotating element and it is applied across diodesmounted with fuses on a diode wheel 174 to energize a rotating fieldelement 176 of the generator 102. Generator voltage is induced in astationary armature winding 178 which supplies current to the powersystem through a generator breaker 136 when the plant 100 issynchronized and on the line. A transformer 180 supplies a feedbacksignal for the regulator 170 to control the excitation level of theexciter field 168. The signal from transformer 180 is also used as thegenerator megawatt signal, a control signal supplied to cabinet 118.

Generally, exciter 154 operates without the use of brushes, slip rings,and external connections to the generator field. Brush wear, carbondust, brush maintenance requirements and brush replacement are therebyeliminated.

All power required to excite generator field 176 is delivered from theexciter-generator shaft. The only external electrical connection isbetween the stationary AC exciter field 168 and the excitationswitchgear 150 (FIG. 1).

In the preferred embodiment, all of the exciter parts are supported bygenerator 102. The generator rotor can be installed and withdrawnwithout requiring removal of the exciter rotor from the generator shaft.

The brushless excitation system regulator 170 responds to average threephase voltage with frequency insensitivity in determining the excitationlevel of the brushless exciter field 168. If the regulator 170 isdisconnected, a motor operated base adjust rheostat 171 is set by acomputer output signal from cabinet 118. The rheostat output is appliedthrough a summing circuit 173 to a thyristor gate control 175. If theregulator 170 is functioning, the base adjust rheostat is left in apreset base excitation position, and a motor operated voltage referenceadjust rheostat 177 is computer adjusted to provide fine generatorvoltage control.

An error detector 179 applies an error output signal to summing circuit173, which error output signal is representative of the differencebetween the computer output reference applied to voltage referencerheostats 177 and the generator voltage feedback signal from transformer180. The summing circuit 173 adds the error signal and the base rheostatsignal in generating the output which is coupled to the gate control175. In error detector 179, the reference voltage is held substantiallyconstant by the use of a temperature compensating Zener diode. In gatecontrol 175, solid state thyristor firing circuitry is employed toproduce a gating pulse which is variable from 0° to 180° with respect tothe voltage supplied to thyristors or silicon controlled rectifiers 180.

The silicon controlled rectifiers 180 are connected in an invertorbridge configuration (not shown) which provides both positive andnegative voltage for forcing the exciter field. However, the exciterfield current cannot reverse. Accordingly, the regulator 170 controlsthe excitation level in exciter field 168 and in turn the generatorvoltage by controlling the cycle angle at which the silicon controlledrectifiers 180 are made conductive in each cycle as level of the outputfrom the gate control 175.

Referring now to FIG. 5, gas turbine 104 in the preferred embodiment isthe W 501D5, a simple cycle type having a rated speed of 3600 rpm. Aswill be apparent from the drawings, turbine 104 includes a two bearingsingle shaft construction, cold-end power drive and axial exhaust.Filtered inlet air enters multistage axial flow compressor 185 throughflanged inlet manifold 183 from inlet ductwork 112. An inlet guide vaneassembly 182 includes vanes supported across the compressor inlet toprovide for surge prevention particularly during startup. The angle atwhich all of the guide vanes are disposed in relation to the gas streamis uniform and controlled by a pneumatically operated positioning ring(not shown) coupled to the vanes in the inlet guide vane assembly 182.

The compressor 185 is provided with a casing 184 which is split intobase and cover halves along a horizontal plane. The turbine casingstructure including the compressor casing 184 provides support for aturbine rotating element, i.e. turbine shaft, through bearings 188 and189. Vibration transducers (FIG. 11) similar to those described inconnection with FIG. 4 are provided for the gas turbine bearings 188 and189. Compressor rotor structure 186 is secured to the turbine shaft inany known manner.

The compressor casing 184 also supports stationary blades 190 insuccessive stationary blade rows along the air flow path. Further,casing 184 operates as a pressure vessel to contain the air flow as itundergoes compression. Bleed flow is obtained under valve control fromintermediate compressor stages according to known techniques to preventsurge during startup.

The compressor inlet air flows annularly through stages in compressor185. Blades 192 mounted on the rotor 186 by means of discs 194 areappropriately designed from an aerodynamic and structural standpoint forthe intended service. Both the compressor inlet and outlet airtemperatures are measured by suitably supported thermocouples (FIG. 11).

Consider now the combustion system. Pressurized compressor outlet air isdirected into a combustion system 196 comprising a total of sixteencan-annular combustors 198 conically mounted within a section 200 of thecasing 184 about the longitudinal axis of the gas turbine 104. Combustorshell pressure is detected by a suitable sensor (FIG. 11) coupled to thecompressor-combustor flow paths and provides a signal to cabinet 118 andpressure switch and gauge cabinet 152.

Combustors 198 are shown to be cross-connected by cross-flame tubes 202for ignition purposes in FIG. 6. A computer enabled sequenced ignitionsystem 204 includes igniters 206 and 208 associated with respectivegroups of four combustors 198. In each group, the combustors 198 areseries cross-connected and the two groups are cross-connected at one endonly as indicated by the reference character 210. The computer generatedenabling signal will be described later. Generally, ignition system 204includes a capacitance discharge ignitor and wiring to respective sparkplugs which form a part of the igniters 206 and 208. The spark plugs aremounted on retractable pistons within the igniters 206 and 208 so thatthe plugs can be withdrawn from the combustion zone after ignition hasbeen executed.

A pair of ultraviolet (UV) flame detectors 212 and 214 are associatedwith each of the end combustors in the respective groups in order toverify ignition and continued presence of combustion in the fourteencombustor baskets 198. Redundancy in flame sensing capability isespecially desirable because of the hot flame detector environment.

Generally, the UV flame detector responds to ultraviolet radiation atwavelengths within the range of 1900-2900 Angstroms which are producedin varying amounts by ordinary combustor flames but not in significantamounts by other elements of the combustor basket environment. Detectorpulses are generated, integrated and amplified to operate a flame relaywhen a flame is present. Ultraviolet radiation produces gas voltagebreakdown which causes a pulse train. The flame monitor adds time delaybefore operating a flame relay if the pulse train exceeds the timedelay.

In FIG. 7, there is shown a front plan view of a dual fuel nozzle 216mounted at the compressor end of each combustor 198. An oil nozzle 218is located at the center of the dual nozzle 216 and an atomizing airnozzle 220 is located circumferentially thereabout. An outer gas nozzle222 is disposed about the atomizing air nozzle 220 to complete theassembly of the fuel nozzle 216. It should be noted that only the mainfuel nozzles for the W 501F turbine have been shown. This turbine alsoincludes a pilot system which is not shown.

As indicated in the section view of FIG. 8, fuel oil or other liquidfuel enters the oil nozzle 218 through conduit 224 while atomizing airenters manifolded 226 through bore 228. Gaseous fuel is emitted throughthe nozzle 222 after flow through entry pipe 230 and manifolded/multiplenozzle arrangement 232. The regulation of fuel flow through conduits 224and 230 will be described later.

Generally, either liquid or gaseous fuel or both liquid and gaseous fuelcan be used in the turbine combustion process. Various gaseous fuels canbe burned including gases ranging from blast furnace gas having low BTUcontent to gases with high BTU content such as natural gas, butane orpropane. However, today's strict environmental regulations limit thefuel considered to natural gas, #2 distillate, and coal derived low BTUgas produced in an integrated gasification combined cycle power plant.

To prevent condensable liquids in the fuel gas from reaching nozzles216, suitable traps and heaters can be employed in the fuel supply line.The maximum value of dust content is set at 0.01 grains per standardcubic foot to prevent excess deposit and erosion. Further corrosion isminimized by limiting the fuel gas sulphur content in the form of H₂ Sto a value no greater than 5% (mole percent).

With respect to liquid fuels, the fuel viscosity must be less than 100SSU at the nozzle to assure proper atomization. Most distillates meetthis requirement. However, most crude oils and residual fuels willrequire additive treatment to meet chemical specifications even if theviscosity specification is met. To prevent excess blade deposition,liquid fuel ash content is limited to maximum values of corrosiveconstituents including vanadium, sodium, calcium and sulphur.

A portion of the compressor outlet air flow combines with the fuel ineach combustor 198 to produce combustion after ignition and the balanceof the compressor outlet air flow combines with the combustion productsfor flow through combustors 198 into a multistage reaction type turbine234 (FIG. 5). The combustor casing section 200 is coupled to a turbinecasing 236 through a vertical casing joint 238. No high pressure air oroil seal is required between the compressor 185 and the turbine 234.

Consider now the torque producing portion of turbine 104 shown in FIG.5. The torque or turbine portion 234 is provided with four reactionstages through which the multiple stream combustion system gas flow isdirected in an annular flow pattern to transform the kinetic energy ofthe heated, pressurized gas into turbine rotation to drive thecompressor 185 and the generator 102. The turbine rotor is formed byfour disc blade assemblies 240, 242, 244 and 245 mounted on a stub shaftby through bolts. Temperature sensing thermocouples (FIG. 11) aresupported within the disc cavities to provide cavity temperature signalsfor the control system. High temperature alloy rotor blades 246 aremounted on the discs in forming the rotor assembly. Individual bladeroots are cooled by air extracted from the outlet of the compressor 185and passed through a coolant system in any suitable manner. The bladeroots thus serve as a heat sink for the rotating blades 246. Cooling airalso flows over each of the turbine discs to provide a relativelyconstant low metal temperature over the unit operating load range.

The two support bearings 188 and 189 for turbine rotating structure arepreferably so-called tilting pad bearings. The bearing housings areexternal to the casing structure to provide for convenient accessibilitythrough the inlet and exhaust ends of the structure. The overall turbinesupport structure provides for free expansion and contraction withoutdisturbance to shaft alignment.

In addition to acting as a pressure containment vessel for the turbine234, the turbine casing 236 supports stationary blades 248 which formstationary blade rows interspersed with the rotor blade rows. Gas flowis discharged from the turbine 234 substantially at atmospheric pressurethrough a flanged exhaust manifold 250 attached to the outlet ductwork114.

The generator and gas turbine vibration transducers (FIG. 11) can beconventional velocity transducers, such as the which transmit basicvibration signals to a vibration monitor for input to the controlsystem, for example, the Bently-Nevada vibration monitor system. A pairof conventional speed detectors (FIGS. 12) are supported at appropriateturbine-generator shaft locations. Signals generated by the speeddetectors are employed in the control system in determining power plantoperation.

A number of thermocouples are associated with the gas turbine bearingoil drains. Further, thermocouples for the blade flow path are supportedabout the inner periphery of the exhaust manifold 250 in any knownmanner to provide a fast response indication of blade temperature forcontrol system usage particularly during plant startup periods. Exhausttemperature detectors are disposed in the exhaust ductwork 114 primarilyfor the purpose of determining average exhaust temperature for controlsystem usage during load operations of the power plan 100. Suitable highresponse shielded thermocouples for the gas turbine 104 are those whichuse compacted alumina insulation with a thin-wall high alloy swagedsheath or well supported by a separate heavy wall guide. Thesignificance of the above described thermocouples and other temperaturedetectors will be described in relation to FIG. 11.

Consider now the fuel system of turbine 104. Referring to FIG. 9, a fuelsystem 251 is provided for the delivery of gaseous fuel to the gasnozzles 222 under controlled fuel valve operation. Gas is transmitted toa diaphragm operated pressure regulating valve 254 from a gas source. Itis noted at this point in the description that IEEE switchgear devicenumbers are generally used herein where appropriate as incorporated inAmerican Standard C37.2-1956.

A starting valve 256 determines gas fuel flow to the nozzles 222 atturbine speeds up to 3600 RPM. Valve 256 is pneumatically positioned bypneumatic actuator 261 in response to a computer generated controlsignal. For ignition, valve 256 is partially open when pneumaticactuator 261 is in its fully closed position. Pressure regulating valve257 provides a constant pressure and thus at ignition a constant gasflow for repeatable gas ignition in the combustion baskets.

As the maximum flow range of the valves 257 and 256 is reached, valve258 opens to control gas flow to the combustion turbines maximum loadoutput.

A pneumatically operated trip valve 260 stops gas fuel flow undermechanical actuation if turbine overspeed reaches a predetermined levelsuch as 110% rated speed. A pneumatically operated vent valve 262 allowstrapped gas to be vented to the atmosphere from trip valve 260 as doeson/off pneumatically operated isolation valve 264. Valves 262 and 264are normally both closed. The isolation valve fuel control action isinitiated by an electronic control signal applied through the pressureswitch and gauge cabinet 152 (FIG. 1 and FIG. 11).

Referring now to FIG. 10, a liquid fuel supply system 266 provides forliquid fuel flow to fourteen nozzles 218 (only eight are shown) from anysuitable fuel source by means of the pumping action of motor driven mainfuel pump 268. Pump discharge pressure is sensed for control system useby a detector 267. A bypass valve 271 is pneumatically operated by anelectropneumatic converter 270 and a booster relay 272 to determineliquid fuel bypass flow to a return line and thereby regulate liquidfuel discharge pressure. A computer generated control signal providesfor pump discharge pressure control, and in particular it provides forramp pump discharge pressure control during turbine startup. A throttlevalve 272 is held at a minimum position during the ramp pressure controlaction on the discharge pressure regulator valve 270. A pressure switch271 indicates whether the pump 268 has pressurized intake flow.

After pressure ramping, the pneumatically operated throttle valve 272 ispositioned to control liquid fuel flow to the nozzles 218 as determinedby a pneumatic actuator 274 and a booster relay 276. A computergenerated control signal determines the converter position controlaction for the throttle valve 272. During such operation, bypass valve270 continues to operate to hold fuel discharge pressure constant.

As in the gas fuel system 251, a mechanically actuated and pneumaticallyoperated overspeed trip valve 278 stops liquid fuel flow in the event ofturbine overspeed. A suitable filter 280 is included in the liquid fuelflow path, and, as in the gas fuel system 251, an electrically actuatedand pneumatically operated isolation valve 282 provides on/off controlof liquid fuel flow to a liquid manifold 283.

Fourteen (only eight are shown) positive displacement pumps 284 arerespectively disposed in the individual liquid fuel flow paths tonozzles 218. Pumps 284 are mounted on a single shaft and they ar drivenby the oil flow from the manifold 283 to produce substantially equalnozzle fuel flows. Check valves 286 prevent back flow from the nozzles218.

Consider now the control system utilized in controlling plant 100. Powerplant 100 is operated under the control of an integratedturbine-generator computer based control system 300 which isschematically illustrated in FIG. 11. The plant control system 300embraces elements disposed in the control cabinet 118, the pressureswitch and gauge cabinet 152 and other elements included in the electricpower plant 100 of FIG. 1. If multiple plants are to be operated, thecontrol system 300 further embodies any additional circuitry needed forthe additional plant operations.

The control system 300 is characterized with centralized systempackaging. Thus, the control cabinet 118 shown in FIG. 1 houses anentire speed/load control package, an automatic plant sequence package,and a systems monitoring package.

As a further benefit to the plant operator, turbine and generatoroperating functions are in the preferred embodiment included on a singleoperator's panel in conformity with the integrated turbine-generatorplant control provided by the control system 300.

The control system 300 provides automatically, reliably and efficientlysequenced start-stop plant operation, monitoring and alarm functions forplant protection and accurately, reliably and efficient performingspeed/load control during plant startup, running operation and shutdown.The plant operator can selectively advance the turbine start cyclethrough discrete steps by manual operation.

Under automatic control power plant 100 can be operated under localoperator control or it can be unattended and operated by remotesupervisory control. Further, the plant 100 is started from rest,accelerated under accurate and efficient control to synchronous speedpreferably in a normal fixed time period to achieve in the general caseextended time between turbine repairs, synchronized manually orautomatically with the power system and loaded under preferred rampcontrol to a pre-selectable constant or temperature limit controlledload level thereby providing better power plant management.

In order to start plant 100, control system 300 first requires certainstatus information generated by operator switches, temperaturemeasurements, pressure switches and other sensor devices. Once it isdetermined that the overall plant status is satisfactory, the plantstartup is initiated under programmed computer control. Plant devicesare started in parallel whenever possible to increase plant availabilityfor power generation purposes. Under program control, completion of onesequence step generally initiates the next sequence step unless ashutdown alarm occurs. Plant availability is further advanced by startupsequencing which provides for multiple ignition attempts in the event ofignition failure.

The starting sequence generally embraces starting and operating thestarting engine to accelerate the gas turbine 104 from low speed,stopping the turning gear, igniting the fuel in the combustion system atabout 20% rated speed, accelerating the gas turbine to about 60% ratedspeed and stopping the starting engine, accelerating the gas turbine 104to synchronous speed, and loading the power after generator breaker 136closure. During shutdown, fuel flow is stopped and the gas turbine 104undergoes a deceleration coastdown. The turning gear is started to drivethe turbine rotating element during the cooling off period.

A control loop arrangement 302 shown in FIG. 12 provides arepresentation of the preferred general control looping embodied incontrol system 300 (FIG. 11) and applicable in a wide variety of otherapplications of the invention. Protection, sequencing, more detailedcontrol functioning and other aspects of the control system operationare subsequently considered more fully herein. In the drawings, SAMAstandard function symbols are employed.

The control loop arrangement 302 comprises an arrangement of blocks ofprocess control loops for use in operating the gas turbine power plant100. No delineation is made in FIG. 12 between hardware and softwareelements since many aspects of the control philosophy can be implementedin hard or soft form.

Generally, a feedforward characterization is preferably used todetermine a representation of fuel demand needed to satisfy speedrequirements. Measured process variables including turbine speed,ambient temperature and pressure, the controlled load variable or theplant megawatts, combustor shell pressure and turbine exhausttemperature are employed to limit, calibrate or control the fuel demandso that apparatus design limits are not exceeded. The characterizationof the feedforward speed fuel demand, a start ramp limit fuel demand anda maximum exhaust temperature limit fuel demand are preferably nonlinearin accordance with the nonlinear characteristics of the gas turbine toachieve more accurate, efficient, available and reliable gas turbineapparatus operation. The control arrangement 302 has capability formaintaining cycle temperature, gas turbine apparatus speed, accelerationrate during startup, loading rate and compressor surge margin.

The fuel demand in the control arrangement 302 provides position controlfor turbine gas or liquid fuel valves, 256, 258 and 272. Further, thecontrol arrangement 302 can provide for simultaneous burning of gas andliquid fuel and it can provide for automatic bumpless transfer from onefuel to the other when required. The subject of bumpless plant transferbetween different fuels and the plant operation associated therewith isknown and has been disclosed in U.S. Pat. No. 3,919,623, incorporatedherein by reference.

In the combination of plural control loop functions shown in FIG. 12, alow fuel demand selector 316 is employed to limit fuel demand byselecting from various fuel limit representations generated by eachcontrol loop. These limit representations are generated respectively byspeed control 303, start ramp control 305, maximum exhaust temperaturecontrol 306, maximum megawatt control 307 and maximum instantaneous loadpickup limiter 308.

During startup and after ignition, start ramp control 305 provides anopen loop fuel demand to accelerate turbine 104 to approximately 80%rated speed. From 80% speed up to and through synchronization, speedcontrol 303 controls turbine 104 to maintain a constant acceleration anddesired speed during synchronization.

After synchronization of generator 102, turbine speed is regulated bythe power system frequency if the power system is large. Consequently,after synchronization speed control 303 regulates fuel flow by rampingthe speed reference signal, generated at 304 by any known technique, inorder to cause a ramping of the megawatt output of generator 102.

In the preferred embodiment, speed control 303 includes proportional,integral, differential (PID) controller 312. A megawatt feedback signalrepresentative of the megawatt output of generator 102 is generated at309 by any known technique and is provided to switch 310. Switch 310provides the megawatt feedback signal to a negative input of controller312 whenever generator breaker control 311 indicates that the generatorbreaker has been closed. A signal representative of turbine speed isgenerated by speed sensor 314, by any known technique, and is providedto another negative input of controller 312. The speed reference signalis provided to the positive input of controller 312.

Since controller 312 will require its inputs to sum zero and since thespeed signal from sensor 314 is essentially constant at synchronization,the speed reference signal will be balanced by the megawatt signal suchthat the output of controller 312 will be representative of a ramping ofthe speed reference signal to pick up load.

As the turbine load, i.e. generator megawatt output, is increased,control loops 305, 306, 307 and 308 can take control of fuel flowthrough low fuel demand select 316 if any of the maximum limitconditions are exceeded. This will indeed happen as the exhausttemperature increases with increasing megawatt output. The maximumexhaust temperature control 307 will eventually control fuel flow toturbine 104 to the maximum allowed temperature.

At low ambient temperatures, maximum megawatt control 308 will becomelow selected before maximum temperature control 307 becomes effective.

At the output of the low fuel demand selector 316, the fuel demandrepresentation is applied to a dual fuel control where the fuel demandsignal is processed to produce a gas fuel demand signal for applicationto the gas starting and throttle valves or a liquid fuel demand signalfor application to the oil throttle and pressure bypass valve or as acombination of gas and liquid fuel demand signals for application to thegas and oil valves together.

The control arrangement 302 generally protects gas turbine apparatusagainst factors including too high loading rates, too high speedexcursions during load transients, too high speed at generator breakerclose, too high fuel flow which may result in overload too low fuel flowwhich may result in combustor system outfires during all defined modesof operation, compressor surge, and excessive turbine inlet exhaust andblade over-temperature. Further, the control arrangement 302 as embodiedin the control system 300 meets all requirements set forth in the NEMApublication "Gas Turbine Governors", SM32-1960 relative to systemstability and transient response and adjustment capability.

Consider now the control system 300 shown in block diagram detail inFIG. 11. It includes a general purpose computer system comprising acentral processor 304 and associated input/output interfacing equipment.

More specifically, the interfacing equipment for the computer 304includes a contact closure input system 306 which scans contact or othersimilar signals representing the status of various plant and equipmentconditions. The status contacts might typically be contacts of mercurywetted relays (not shown) which are operated by energization circuits(not shown) capable of sensing the predetermined conditions associatedwith the various plant devices. Status contact data is used for examplein interlock logic functioning in control and sequence programs,protection and alarm system functioning, and programmed monitoring andlogging.

Input interfacing is also provided for the computer 304 by aconventional analog input system 328 which samples analog signals fromthe gas turbine power plant 100 at a predetermined rate for each analogchannel input and converts the signal samples to digital values forcomputer processing. A conventional printer 330 is also included and itis used for purposed including for example logging printouts asindicated by the reference character 332.

Output interfacing generally is provided for the computer by means of aconventional contact closure output system 326. Analog outputs aretransmitted through the contact closure output system 326 under programcontrol.

The plant battery 135 considered previously in connection with FIG. 1 isalso illustrated since it provides necessary supply voltages foroperating the computer system, control system and other elements in thepower plant 100. Battery charging is provided by a suitable charger 320.

Connections are made to the contact closure input system 326 fromvarious turbine, protective relay, switchgear, pressure switch and gaugecabinet, and starting engine contacts. In addition certain customerselected contacts 327D and miscellaneous contacts 327C such as those inthe motor control center 134 are coupled to the contact closure inputsystem 326.

Analog/digital (A/D) input system 328 has applied to it the outputs fromvarious plant process sensors or detectors, many of which have alreadybeen briefly considered. Various analog signals are generated by sensorsassociated with the gas turbine 104 for input to the computer system 334where they are processed for various purposes. The turbine sensors 329A-K include multiple blade path thermocouples, disc cavitythermocouples, exhaust manifold thermocouples, bearing thermocouples,compressor inlet and discharge thermocouples, and, as designated by theblock marked miscellaneous sensors, oil reservoir thermocouple, bearingoil thermocouple, a main fuel inlet thermocouple, ambient airtemperature sensor and an ambient air pressure sensor.

The signals generated by the ambient air temperature apparent inrelation to the control circuit shown in FIG. 13. The sensor used tomeasure ambient temperature can be any known device such as athermocouple. Ambient air temperature and ambient air pressure arepreferably measured at the compressor inlet.

A combustor shell pressure sensor and a main speed sensor and a backupspeed sensor also have their output signals coupled to the analog inputsystem 328. A turbine support metal thermocouple is included in themiscellaneous block 329K.

Sensors 329 L-R associated with the generator 102 and the plantswitchgear are also coupled to the computer 334. The generatortemperature sensors include stator resistance temperature detectors, aninlet air thermocouple, an outlet air thermocouple, and bearing drainthermocouples. Vibration sensors associated with the generator 102 andthe gas turbine 104 are coupled with the analog input system 328 throughthe operator's console 120 where the rotating equipment vibration can bemonitored. As indicated by FIG. 11, additional sensors which are locatedin the protective relay cabinet generate signals representative ofvarious bus, line, generator and exciter electrical conditions.

Other devices operated by contact closure outputs include the generatorfield breaker and the generator and line breakers 136, 138 and 139. Themotor operated generator exciter field rheostats 171 and 177 and variousdevices in the motor control center 134 and the pressure switch andgauge cabinet 152 also function in response to contact closure outputs.The printer 330 is operated directly in a special input/output channelto central processor 334.

The ignition air flow controller is more particularly disclosed in FIG.13. It will be recalled that the ignition air flow controller detectsoptimum air flow for ignition of turbine 104. The chances for ignitionin large combustion turbines can be maximized if both fuel and air floware maintained consistent with stability and/or flammability limits fora particular basket and nozzle configuration. Such limits should bebelow levels which would cause thermal damage to the turbine sections.

Generally, it is impractical to measure air flow through the turbinedirectly because the presence of a flow meter or flow sensor would causeunacceptable performance penalties. Additionally, ignition air flow hasa significantly smaller magnitude when compared to full outputconditions. Consequently, ignition air flow would be difficult tomeasure accurately utilizing known delta pressure methods. Althoughso-called hot wires and anemometers could be utilized, their accuracyand reliability are suspect.

The goal in turbine ignition is to begin the ignition process when airflow is at an optimum. During operation, starting motor 126 slowlyincreases the speed of the turbine and thus air flow. If there were noexternal factors influencing air flow through the turbine, one couldsimply sense turbine speed and, as was done in prior turbines, begin theignition process when turbine speed reached a preselected value.However, ambient air temperature and pressure can effect the amount ofair flow through a turbine at a given speed. For example a turbinespinning at 3600 RPM on an 80° day could have identical air flow as thatsame turbine on a 59° F. day operating at 3400 RPM. The presentinvention accounts for this "effective turbine speed" condition andinitiates the ignition process when the effective turbine speed reachesa preset reference speed level. The output of the air flow controller isutilized to enable ignition system 204.

In the control circuit shown in the FIG. 13, speed, ambient temperature,and, in the preferred embodiment, ambient pressure are measured. Thecombination of these measurements, after appropriate biasing, arecompared with a known ignition set point speed. It should be noted thatthe ignition set point is representative of that turbine speed whereoptimum ignition air flow will occur. For example on a day when ambienttemperature is 59° F. and ambient pressure is 29.92 inches mercury theignition set point would be 720 RPM. In the present invention, when theadjusted speed signal reaches the ignition set point speed, optimumignition conditions are present and the controller will generate anignition enabling signal.

As shown in FIG. 13, a summer 450 is utilized to combine signalsrepresentative of turbine speed, ambient temperature and ambientpressure. The turbine speed signal is provided at 452, having beengenerated by the speed sensor shown in FIG. 11. Ambient temperaturehaving been measured by any known method at the compressor inlet isprovided to bias block 454. In response to the ambient temperaturesignal, biased block 454 generates a temperature based speed bias signalfor appropriate combination with the turbine speed signal in summer 450.The ambient pressure signal, having been measured and generated in anyknown fashion, is provided to biased block 456. Similar to biased block454, biased block 456 generates a pressure based speed bias signal to becombined with the turbine speed signal in summer 450.

As will be apparent from the above, the effect of processing the ambienttemperature and pressure signals in bias blocks 454 and 456 is togenerate a turbine speed compensation factor or bias signal which whenadded to the actual speed signal results in ignition occurring at thatturbine speed wherein optimum air flow conditions exist. For example, inthe W 501F turbine of the preferred embodiment, ignition will occur atapproximately 20 percent rated speed or 720 RPM.

The speed bias signals are generated in relation to air flowcharacteristic curves for a given turbine relating to ambient airtemperature and pressure. In the preferred embodiment, for example, suchair flow characteristics indicate that as ambient air temperature variesabove and below 59° F. turbine air flow can vary by as much as 13percent. Consequently, in order to assure that ignition occurs atoptimum air flow conditions, the controller of the present inventionadjusts the actual turbine speed signal so that the reference speedprovided by signal generator 460 is not reached until actual turbinespeed is sufficient to provide optimum air flow. Since the type ofturbine is known and since air flow characteristics for such turbine arealso known, bias blocks 454 and 456 can be arranged in a so-calledlook-up table format.

The output of summer 450 is provided to comparator 458. Comparator 458compares the summed signal with the turbine speed set point signalgenerated by reference block 460. As indicated previously, when themodified speed signal from summer 450 reaches the speed referencesignal, comparator 458 provides an enabling signal to start the ignitionprocess. At all other times when the adjusted actual turbine speed isless than the speed set point, the output of comparator 458 serves toprevent the enablement of the ignition process.

While the invention has been described and illustrated with reference tospecific embodiments, those skilled in the art will recognize thatmodification and variations may be made without departing from theprinciples of the invention as described herein above and set forth inthe following claims.

What is claimed is:
 1. Apparatus for generating an ignition enablingsignal for use with a given combustion turbine, wherein a turbine speedsignal is given and wherein said combustion turbine includes ignitionmeans for igniting said turbine in response to an ignition enablingsignal, said apparatus comprising,sensor means for sensing thetemperature of ambient air and for generating an ambient air temperaturesignal; reference means for generating a reference signal representativeof the turbine speed at which optimum air flow exists for ignition ofsaid combustion turbine; comparator means for comparing said referencesignal to an adjusted speed signal, for generating said ignitionenabling signal when said adjusted speed signal exceeds said referencesignal and for providing said ignition enabling signal to said ignitionmeans; processing means for generating said adjusted speed signal bymodifying said turbine speed signal in response to said ambient airtemperature signal; and second sensing means for sensing the ambient airpressure and for generating an ambient air pressure signal wherein saidprocessing means for generating said adjusted speed signal also modifiessaid turbine speed signal in response to said ambient air pressuresignal.
 2. The apparatus of claim 1, wherein said sensor means comprisesa thermocouple positioned to measure air temperature at the compressorinlet.
 3. The apparatus of claim 1, further comprising bias means, saidbias means comprising a look-up table representative of the differencebetween optimum turbine ignition speed and that turbine speed necessaryfor optimum ignition air flow to exist in said combustion turbine at thesensed ambient air temperature.
 4. An electric power plant, comprising:acombustion turbine having a shaft, said combustion turbine beingoperative to turn said shaft in response to the combustion of fuel insaid turbine and said combustion turbine having ignition means to ignitesaid fuel in response to an ignition enabling signal; a generatorconnected to said shaft so that electric power is produced when saidturbine shaft turns; first reference means for generating a speed signalrepresentative of actual turbine speed; sensor means for sensing thetemperature of ambient air and for generating an ambient air temperaturesignal; second reference means for generating a second reference signalrepresentative of the turbine speed at which optimum air flow exists forignition of said combustion turbine; comparator means for comparing saidsecond reference signal to an adjusted speed signal, for generating saidenabling signal when said adjusted speed signal exceeds said secondreference signal and for providing said ignition enabling signal to saidignition means; processing means for generating said adjusted speedsignal by modifying said turbine speed signal in response to saidambient air temperature signal; and second sensing means for sensing theambient air pressure and for generating an ambient air pressure signalwherein said processing means for generating said adjusted speed signalalso modifies said turbine speed signal in response to said ambient airpressure signal.
 5. The apparatus of claim 4, wherein said sensor meanscomprises a thermocouple positioned to measure air temperature at thecompressor inlet.
 6. The apparatus of claim 4, wherein said processingmeans comprises summing means for summing said turbine speed signal witha bias speed factor and bias means for generating said bias speed factorin response to said ambient air temperature signal.
 7. The apparatus ofclaim 6, wherein said bias means comprises a look-up tablerepresentative of the difference between optimum turbine ignition speedand that turbine speed necessary for optimum ignition air flow to existin said combustion turbine at the sensed ambient air temperature.
 8. Amethod for generating an ignition enabling signal for use with a givencombustion turbine, wherein a turbine speed signal is given and whereinsaid combustion turbine includes ignition means for igniting saidturbine in response to an ignition enabling signal, said methodcomprising the steps of:sensing the temperature of ambient air and forgenerating an ambient air temperature signal; generating a referencesignal representative of the turbine speed at which optimum air flowexists for ignition of said combustion turbine; generating an adjustedspeed signal by modifying said turbine speed signal in response to saidambient air temperature signal; and comparing said reference signal tosaid adjusted speed signal, generating said ignition enabling signalwhen said adjusted speed signal reaches said reference signal andproviding said ignition enabling signal to said ignition means; andsensing the ambient air pressure, generating an ambient air pressuresignal, generating a bias speed factor in response to said ambient airpressure signal, wherein said bias speed factor is also added to saidturbine speed signal by said step of summing.
 9. The method of claim 8,wherein the step of sensing said ambient air temperature comprisespositioning a thermocouple to measure air temperature at the compressorinlet.
 10. The method of claim 8, wherein the step of generating anadjusted speed signal comprises summing said turbine speed signal with asecond bias speed factor and generating said second bias speed factor inresponse to said ambient air temperature signal.
 11. The method of claim10, wherein said step of generating said second bias speed factorcomprises the step of providing a look-up table representative of thedifference between optimum turbine ignition speed and that turbine speednecessary for optimum ignition air flow to exist in said combustionturbine.
 12. The apparatus of claim 1, wherein said processing meanscomprises summing means for summing said turbine speed signal with abias speed factor and bias means for generating said bias speed factorin response to said ambient air temperature signal and second bias meansfor generating a second bias speed factor in response to said ambientair pressure signal, wherein said second bias speed factor is also addedto said turbine speed signal by said summer means.
 13. The apparatus ofclaim 6, further comprising second bias means for generating a secondbias speed factor in response to said ambient air pressure signal,wherein said second bias speed factor is also added to said turbinespeed signal by said summer means.